As described in International patent application WO 2008/029124, it is known to inject water of low salinity into an oil-bearing formation of a reservoir in order to enhance the recovery of oil from the reservoir.
A problem associated with low salinity water-flooding is that desalination techniques may yield water having a salinity lower than the optimal salinity for enhanced oil recovery. Indeed, the desalinated water may be damaging to the oil-bearing rock formation of the reservoir and inhibit oil recovery, for example, by causing swelling of clays in the formation. There is an optimal salinity for the injection water that provides the benefit of enhanced oil recovery whilst avoiding formation damage, and, the optimum value will vary from formation to formation. Typically, where an oil-bearing formation comprises rock that contains high levels of swelling clays, formation damage may be avoided when the injection water has a total dissolved solids content (TPS) in the range of 500 to 5,000 ppm, preferably, 1,000 to 5,000 ppm.
However, it is not desirable to mix a desalinated water of low multivalent cation content with a high salinity water such as seawater owing to the high sulfate anion content and/or high multivalent cation content of the high salinity water. Thus, the high sulfate anion content of the such mixed water streams may result in reservoir souring and/or the precipitation of unacceptable levels of insoluble mineral salts (scale formation) when the injected water contacts precipitate precursor cations such as barium, strontium and calcium cations that are commonly present in the connate water of the formation. In addition, mixing of desalinated water with a high salinity water such as seawater may result in the mixed water stream containing unacceptable levels of multivalent cations, in particular, calcium and magnesium cations. Thus, in order to achieve incremental oil recovery with a low salinity injection water, the ratio of the concentration of multivalent cations in the low salinity injection water to the concentration of multivalent cations in the connate water of the reservoir should be less than 1, preferably, less than 0.9, more preferably, less than 0.8, in particular, less than 0.6, for example, less than 0.5.
As described in International patent application WO 2007/138327, one way in which the salinity of a water supply of overly low salinity might be increased is by blending with water of higher salinity. According to WO 2007/138327, this may be achieved by the steps of:                substantially desalinating a first feed supply of water to provide a first supply of treated water of low salinity;        treating a second feed supply of water to provide a second supply of treated water having a reduced concentration of divalent ions in comparison to the second feed supply and a higher salinity than the first supply of treated water; and        mixing the first supply of treated water and the second supply of treated water to provide a supply of mixed water having a desired salinity suitable for injection into an oil bearing reservoir.        
In preferred embodiments of the invention of WO 2007/138327, the first feed supply is substantially desalinated by a reverse osmosis process while the step of treating the second feed supply of water is preferably performed by nanofiltration.
Nanofiltration is commonly used in the oil industry to remove sulfate ions from a source water. The treated water can then be injected into a formation without the risk of forming unacceptable levels of insoluble mineral salts when the injected water contacts precipitate precursor cations present in the connate water of the formation. The invention of WO 2007/13832 therefore permits the supply of a mixed water having the desired salinity suitable for injection into the oil bearing reservoir and having a reduced level of sulfate anions thereby mitigating the risk of mineral scale precipitation either within the formation or in production wells.
It is known that injection of a water that contains high levels of sulfate anions can stimulate the growth of sulfate reducing bacteria that produce hydrogen sulfide as a metabolite resulting in souring of a reservoir. Where it is desired to mitigate the risk of mineral scale formation, the Level of sulfate anions in the supply of mixed water should be less than 40 ppm. However, where it is desired to mitigate the risk of souring in a reservoir, the level of sulfate anions in the supply of mixed water should be as low as possible, for example, less than 7.5 ppm, preferably, less than 5 ppm.